REDI RENEWABLE ENERGY DEVELOPMENT INFRASTRUCTURE
Connecting Colorado’s Renewable Resources to the Markets in a Carbon-Constrained Electricity Sector
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Acronyms and Abbreviations . . . . . . . . 5
Executive Summary— Major Assumptions and Findings 6
I. The 20X20 Goal: Reducing Carbon Dioxide in Colorado’s Electricity Sector by 20 Percent by 2020 from 2005 CO2 Levels 10
What is the basis for the proposed 20x20 goal in the REDI Report? . . . . . . . . . . 12
What is Colorado’s CO2 emission profile, and how much is attributable to the elec- tricity sector? . . . . . . . . . . . . . . . . . . . . 12
Why is transmission so important in how the electric power system operates? . 12
What is the history of the Rocky Moun- tain region’s electric generation and fuel type? . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
How does population growth affect the demand for electric power?. . . . . . . . . .15
How can demand-side measures help meet the 20x20 goal? . . . . . . . . . . . . . .17
What is distributed generation, and how is that concept emerging in Colorado? 18
Can demand-side measures mitigate or eliminate the need for new central power
stations and new transmission? . . . . 18
How can utility-scale renewable resources help meet the 20x20 goal? . . . . . . . . . 19
How can natural gas-fired generating plants help meet the 20x20 goal? . . . 20
What is the role of coal-fired generation regarding the 20x20 goal? . . . . . . . . . 21
What policy and other steps have been taken in the past few years to move toward the 20x20 goal? . . . . . . . . . . . 22
What high-voltage transmission develop- ments are under way at Tri-State?. . . . 26
Is transmission infrastructure sufficient either in Colorado or nearby to deliver the renewable energy needed to meet a 20x20 goal? . . . . . . . . . . . . . . . . . . . . . 28
How did Colorado’s existing wind farms address transmission issues? . . . . . . . 30
What potential technology and policy development “game-changers” could influence the path to the 20x20 goal? 30
What about placing high-voltage trans- mission underground? . . . . . . . . . . . . .35
Do we know what new transmission may cost? . . . . . . . . . . . . . . . . . . . . . . . . . . 36
What are the potential benefits of trans- mission?. . . . . . . . . . . . . . . . . . . . . . . . 37
Can we estimate the cost and benefits of a major increase in utility-scale renew- able energy generation and high-voltage transmission? . . . . . . . . . . . . . . . . . . . 38
Is it practical for a transmission line to be built exclusively for transmission of renewable energy? . . . . . . . . . . . . . . . . 39
II. Where We Are Today 41
Colorado’s Transmission Context . . . . 41
How is transmission relevant to eco- nomic development, renewable energy development, job creation, and environ- mental quality?. . . . . . . . . . . . . . . . . . . 41
What is the mix of resources available to meet society’s electric power needs? . 41
Who decides what mix of resources to deploy? . . . . . . . . . . . . . . . . . . . . . . . . . 42
Colorado has identified renewable resource GDAs. Do these GDAs have suf- ficient high-voltage transmission? . . . 42
Is Colorado’s transmission system already constrained and do those con- straints affect the ability to build and integrate new renewable generation? . 42
Why is Colorado’s renewable energy development not happening faster? . . 44
Colorado Transmission Policy Issues . 45
What are the roles and functions of differ- ent types of generating resources in the overall power system? . . . . . . . . . . . . 46
How does transmission planning pose a challenge? . . . . . . . . . . . . . . . . . . . . . . 47
Does the advent of concerns about carbon dioxide change planning require- ments? . . . . . . . . . . . . . . . . . . . . . . . . . 47
The Renewable Energy Development Infrastructure (REDI) Report
Connecting Colorado’s Renewable Resources to the Markets in a Carbon-Constrained Electricity Sector Colorado Governor’s Energy Office
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What are “independent transmission companies” and what role do they play— or could they play—in Colorado? . . . . 49
From an engineering standpoint, how difficult is it to replace high-carbon resources with zero-carbon supply-side resources? . . . . . . . . . . . . . . . . . . . . . . 49
What are the physical characteristics of the current wholesale electricity market in Colorado?. . . . . . . . . . . . . . . . . . . . . . . 52
What proposals now exist to significantly expand interstate transmission? . . . . 52
What are the limitations of Colorado’s transmission system within the regional context? . . . . . . . . . . . . . . . . . . . . . . . . .55
What are the economic characteristics of Colorado’s current wholesale power market? . . . . . . . . . . . . . . . . . . . . . . . . .55
How do organized wholesale markets elsewhere in the nation approach renew- able energy, transmission, and grid operations? . . . . . . . . . . . . . . . . . . . . . 56
How are other Western states meeting renewable energy goals? . . . . . . . . . . . 57
How are Western states identifying the best renewable energy resources? . . . 58
Colorado has more utility-scale renewable energy potential than it needs in-state. What are the opportunities to export it?. 60
What is transmission rate pancaking? 61
What plans are there for solar energy
development in Colorado’s San Luis Valley? . . . . . . . . . . . . . . . . . . . . . 61
What are Colorado’s competitive advan- tages with respect to renewable energy manufacturing? . . . . . . . . . . . . . . . . . . 62
III. Land Use, Environment, Permitting, and Siting 64
Ecological and Other Concerns . . . . . 64
What limitations do wildlife habitat, plant species, or restricted military lands impose on the ability to build new renewable generation or transmission in Colorado? . . . . . . . . . . . . . . . . . . . . . . 64
Aside from wildlife-related concerns, what other concerns must developers consider when building transmission or renewable generation? . . . . . . . . . . . . . . . . . . . . . 67
What land use regulatory procedures must a company seeking to build new renewable energy generation or new transmission go through in order to ob- tain permission to build on federal, state, or county lands? . . . . . . . . . . . . . . . . . 70
Federal Permitting . . . . . . . . . . . . . . . . 70
What are the current county permitting requirements across Colorado? . . . . . 72
Do Colorado’s county processes impose a burden on the overall process of siting for new transmission or renewable gen- eration? . . . . . . . . . . . . . . . . . . . . . . . . 73
Acquiring Rights on Private Lands . . . 74
Aside from the governmental permitting process, what is the process for acquir- ing permission to use private lands for transmission? . . . . . . . . . . . . . . . . . . . 74
What renewable energy and transmission opportunities are there on the Colorado State Board Land Commissions’ prop- erty? . . . . . . . . . . . . . . . . . . . . . . . . . . . 74
The Federal Context. . . . . . . . . . . . . . . 76
The American Recovery and Reinvest- ment Act of 2009 . . . . . . . . . . . . . . . . 79
IV. Gaps & Options to Address Them 81
Transmission System Planning and Op- erations . . . . . . . . . . . . . . . . . . . . . . . . 81
Transmission Siting and Permitting . . 84
V. Conclusions 87
Appendix I. Summary of Modeling — University of Colorado at Denver College of Engineering . . . . . . . . . . . . . . . . . . . 88
Appendix II. Terminology . . . . . . . . . . 92
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Preface
The National Academy of Engineering ranked electric power as the greatest engineering achievement of the 20th Cen- tury.1 Electric power is the lifeblood of our economy. We expect that the next decade will result in dramatic changes in how we produce, transmit, and make produc- tive use of electricity. We offer this report to provide Colorado citizens and other interested stakeholders with information to help bring about positive changes in the electricity sector.
Addressing 600 people at the Third Annual New Energy Economy Conference on October 20, 2009,2 Colorado Gover- nor Bill Ritter said:
“We are working on a tremendous energy challenge facing us today: trans- mission — a way to move electrons from clean energy sources to where they’re in greatest demand. In Colorado — indeed in much of the country — many of our best renewable energy sources are a long way from the places that require the most electricity. We need a new effort at col- laboration to ensure wind power on the Eastern Plains and solar power in the San Luis Valley can travel to the load centers of the Front Range. We must work more closely together and plan with greater
foresight to ensure needed transmission for utility-scale renewable power. We must be open to more regional and state- to-state cooperation, and consider new approaches for how transmission is built, and how we pay for it. To this point, my energy office is releasing an important report: The Renewable Energy Develop- ment Infrastructure, or REDI, report. The report — the result of a partnership with the DOE — discusses in great detail the need for transmission in our New Energy Economy, the challenges we face and suggestions on how to move the effort forward.”
On behalf of the Colorado Governor’s Energy Office (GEO), we thank you for your interest in the REDI Project.
The REDI Project includes the REDI Report, the REDI Project’s consultants’ research (“the Technical Reports”) and two REDI videos. The project was designed to expand the discussion re- garding Colorado’s options on how the state’s electricity sector3 can best plan for its near-term future in a carbon-con- strained world. The Technical Reports contain 450 pages of specific results that helped provide factual data, insights, and analysis for the REDI Project. The full output of the REDI Project is acces- sible on the GEO website: www.colo-
rado.gov/energy go to Electric Utilities, then to the REDI Project.
Purpose
The benchmark goal that drives the re- port is to achieve a 20 percent reduction in carbon dioxide (CO2) emissions in Colorado’s electricity sector below 2005 levels by 2020. We refer to this as the “20x20 goal.” In discussing how to meet this goal, the report concentrates particu- larly on the role of utility-scale renewable energy and high-voltage transmission4.
An underlying recognition is that any proposed actions must not interfere with electric system reliability and should minimize financial impacts on customers and utilities. The report also describes the goals of Colorado’s New Energy Economy5 — identified here, in summary, as the integration of energy, environment, and economic policies that leads to an increased quality of life in Colorado.
We recognize that a wide array of options are under constant consider- ation by professionals in the electric industry, and the regulatory community. Many options are under discussion on this topic, and the costs and benefits of the options are inherently difficult to quantify. Accordingly, this report should not be viewed as a blueprint with specific
recommendations for the timing, siting, and sizing of generating plants and high- voltage transmission lines. We convened the project with the goal of supplying information inputs for consideration by the state’s electric utilities, legislators, regulators, and others as we work cre- atively to shape our electricity sector in a carbon-constrained world.
The report addresses various is- sues that were raised in the Connecting Colorado’s Renewable Resources to the Markets report, also known as the SB07- 91 Report.6 That report was produced by the Senate Bill 2007-91 Renewable Resource Generation Development Areas Task Force and presented to the Colorado General Assembly in 2007. The SB07-91 Report provided the Governor, the General Assembly, and the people of Colorado with an assessment of the capability of Colorado’s utility-scale renewable resources to contribute electric power in the state from 10 Colorado gen- eration development areas (GDAs) that have the capacity for more than 96,000 megawatts (MW) of wind generation and 26,000 MW of solar generation. The SB07-91 Report recognized that only a small fraction of these large capacity op- portunities are destined to be developed. As a rough comparison, 13,964 MW of
Preface, Purpose, and Acknowledgments
installed nameplate capacity was avail- able in Colorado in 2008.
The legislature did not direct the SB07-91 task force to examine several issues that are addressed in the REDI report. These issues include topics such as transmission, regulation, wildlife, land use, permitting, electricity demand, and the roles that different combinations of supply-side resources, demand-side resources, and transmission can play to meet a CO2 emissions reduction goal. This report, which expands upon research from a wide array of sources, serves as a sequel to the SB07-91 Report.
Reports and research on renew- able energy and transmission abound. This report builds on the work of many, including professionals who have dedicated their careers to these topics. A bibliography of information resources is provided, along with many citations to the work of others.
The REDI Project was designed to present baseline information regarding the current status of Colorado’s genera- tion and transmission infrastructure. The report discusses proposals to expand the infrastructure, and identifies opportuni- ties to make further improvements in the state’s regulatory and policy environ- ment. The report offers a variety of op-
tions for consideration as Colorado seeks pathways to meet the 20x20 goal.
The primary goal of the report is to foster broader discussion regarding how the 20x20 goal interacts with electric resource portfolio choices, particularly the expansion of utility-scale renewable energy and the high-voltage transmis- sion infrastructure. The report also is intended to serve as a resource when identifying opportunities stemming from the American Recovery and Reinvest- ment Act of 2009.
Acknowledgments
The Colorado Governor’s Energy Of- fice (GEO) was awarded a grant from the U.S. Department of Energy’s (DOE) Office of Electricity Delivery and Energy Reliability to support the REDI Project. The DOE solicitation considered propos- als that would lead to development of a minimum of 1,000 MW of new renewable energy capacity in the applicant’s state. After receiving the DOE grant, and follow- ing a competitive bidding process, GEO retained contractors to conduct research, writing, and project management ser- vices. The REDI Project team members included technical consultants from the National Renewable Energy Laboratory (NREL), the University of Colorado-
Denver College of Engineering, Navarro- E2MG, R.W. Beck, and WorleyParsons. GEO also contracted with Skeeter Buck for administrative support; David Skiles for GIS work and other deliverables, and John Boak, who designed the report, the full-page maps, charts, and other design work for the report.
The REDI consultants’ scopes of work and research tasks were guided by the report authors. The REDI Project greatly appreciates the detailed collec- tion of data, and preparation of analyses produced by the consultants. The REDI consultants’ research findings are inde- pendent results, however, and their data and conclusions should not be viewed as formal findings by the GEO and the DOE. A primary value of the REDI Project is derived by reading the techni- cal reports, which can be downloaded from the REDI page on GEO’s website at www.colorado.gov/energy.
The following reports were prepared by the REDI consultants:
The University of Colorado-Denver (UCD) College of Engineering report was prepared by Dr. Saeed Barhaghi, Engineering Research Professor at the UCD College of Engineering. The 53-page report, Renewable Energy Development Infrastructure Project: Colorado Climate
Action Plan Scenario Analysis For Colo- rado’s Power Sector focuses on a narrative of the approach taken and the results of the computer modeling of the 20x20 goal. A summary of the modeling work is located in Appendix I of this report.
The Navarro-E2MG report also was prepared by Dr. Saeed Barhaghi. The 102- page report, Renewable Energy Develop- ment Infrastructure Project: Colorado Generation and Transmission: A Baseline Assessment provides readers with a de- tailed quantification of Colorado’s genera- tion and transmission infrastructure.
The R.W. Beck report was prepared by Bahman Daryanian and his colleagues at R.W. Beck. The 199-page report, Renew- able Energy Development Infrastructure Project: Regulatory and Economic Analysis provides detailed information about the regulatory, financial, and economic aspects of generation and transmission development.
The WorleyParsons (WP) report was prepared by a team of consultants at WP. The 60-page report, Renewable Energy Development Infrastructure Project: En- vironmental, Siting, and Land Use Issues addresses constraints to renewable energy and transmission developments in the GDAs. It also addresses ecological features, and the land use jurisdictions
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that affect project permitting and project location.
The National Renewable Energy Laboratory report was prepared by David Hurlbut, NREL Economist. The 30-page report, Colorado’s Prospects for Interstate Commerce in Renewable Energy, focuses on the potential export market for Colo- rado’s utility-scale renewable energy.
The REDI project team received input from an advisory board com- posed of: Eugene Camp, representing the Staff of the Colorado Public Utilities Commission; Craig Cox, representing Interwest Energy Alliance; Tom Darin, representing Western Resource Advo- cates; Rick Gilliam, representing the Solar Alliance; Ethnie Groves Treick, representing Public Service Company of Colorado; Ron Lehr, representing the American Wind Energy Association; Dill Ramsay and Ron Steinbach, represent- ing Tri-State Generation and Trans- mission Association; and Lee White, representing the Colorado Clean Energy Development Authority. Advisory board members served only in an advisory capacity. The members of the advisory board do not expressly endorse the data or the findings contained in the report and the REDI contractors’ tech- nical reports.
The report is a product of the GEO, operating under a contract from the DOE. The authors of the report are Mat- thew H. Brown, Partner, ConoverBrown, a contractor to the GEO, who served as project manager; David Hurlbut, Econo- mist, National Renewable Energy Labora- tory, who contracted with GEO under a Technical Services Agreement; and Morey Wolfson, GEO’s Transmission Program Manager, who served as the principal investigator. Corrections to the report should be directed to: morey.wolfson@ state.co.us
Acronyms and Abbreviations
ATC Available Transmission Capability
CPCN Certificate of Public Conve- nience and Necessity
CLRTPG Colorado Long-Range Trans- mission Planning Group
CREZ Competitive Renewable Energy Zones
DOE U.S. Department of Energy
EIA Energy Information Adminis- tration (USDOE)
EPTP Eastern Plains Transmission Project
ERCOT Electric Reliability Council of Texas
ERZ Energy Resource Zone
GDA Generation Development Area
HPX High Plains Express Transmis- sion Project
IOU Investor-owned utility
MEAN Municipal Energy Agency of Nebraska
NERC North American Electricity Reliability Corporation
NREL National Renewable Energy Laboratory
PSCo Public Service Company of Colorado
PUC Colorado Public Utilities Com- mission
REDI Renewable Energy Develop- ment Infrastructure
SB07-091 Colorado Senate Bill 2007-091 Renewable Resource GDA Task Force
SPP Southwest Power Pool
SWAT Southwest Area Transmission
UCD University of Colorado at Den- ver
USDOE United States Department of Energy
WAPA Western Area Power Adminis- tration
WGA Western Governors’ Associa- tion
WP WorleyParsons
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Colorado’s electricity sector is mov- ing into an era where it must address a relatively new challenge — carbon dioxide (CO2) emission reduction. And in so doing, the sector must continue to emphasize system reliability, the need for infrastructure upgrades, and strate- gic planning to minimize the economic and environmental costs into the future. These, and other, interrelated challenges are the subject of the Colorado Gover- nor’s Office’s (GEO) 100-page Renew- able Energy Development Infrastructure (REDI) Report.
Colorado is fortunate to have some of the most abundant utility-scale renewable resource generation development areas (GDAs) in the nation. To bring that power to the market requires high-voltage trans- mission infrastructure. Developing Colo- rado’s resources as a means to achieve climate change and economic develop- ment opportunity offers an unprecedented opportunity for the state to lead the nation and take full advantage of the New Energy Economy. Leadership in Colorado’s elec- tricity sector that successfully addresses the inter-related challenges, including pur- suing a CO2 reduction strategy, will create new jobs, will revitalize many of our rural economies, and will help ensure long-term cost stability for electric customers.
The report examines how Colorado’s electricity sector can reduce its CO2 emissions by 20 percent by 2020 from its 2005 levels — referred to as the “20x20 goal.” The report focuses particularly on this question: how can Colorado most effectively address the challenge of build- ing new high-voltage transmission lines to deliver utility-scale renewable power from Colorado’s rich renewable resource generation development areas to the markets?
The electricity sector nationally, and in Colorado, is increasing its recognition of and commitment to the need to meet CO2 reduction goals. As Colorado’s elec- tricity sector addresses the 20x20 goal, industry and regulators will also address electric demand growth, water con- straints, and the urgent need to upgrade an aging and undersized transmission in- frastructure. The report focuses primarily on high-voltage transmission and supply- side electric power options, but it does so within the context of how an appropriate blend of demand-side and supply-side measures can most cost-effectively meet the 20x20 goal.
The map that follows shows Colorado’s existing high-voltage transmission infra- structure, defined as 115 kilovolts (kV) and above. Colorado does not have transmis-
sion lines with voltages above 345 kV. The map also shows the renewable resource GDAs identified in the Connecting Colo- rado’s Renewable Resources to the Markets, also known as the SB07-91 Report, where the state’s highest concentrations of high- quality wind and solar resources exist. Lines rated at 115 kV are only capable of deliver- ing very modest blocks of power. Higher voltages lines, such as 230, 345, and 500kV lines are far more effective of delivering Colorado’s rich renewable resources to the markets. Most of the high-voltage trans- mission lines in or near the GDAs already are constrained, with little spare transfer capability to accommodate new renewable power development. High-voltage trans- mission delivering renewable power to the markets will greatly facilitate Colorado’s opportunities to reduce CO2 emissions while expanding the state’s economic development.
The REDI Report uses three Colorado electricity sector CO2 emission scenarios to examine how Colorado might achieve the 20x20 goal. The REDI Project’s technical consultant, at the University of Colorado at Denver’s (UCD) College of En- gineering, developed the quantification of these goals. To conduct the analysis, it was necessary to construct plausible scenarios for the future of Colorado’s electricity
Executive Summary—Major Assumptions and Findings
The report examines how
Colorado’s electricity sector
The report refers to this as
the “20x20 goal.”
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sector. These scenarios do not constitute formal policy goals, nor are they specific policy recommendations. The analysis of how Colorado’s electricity sector can meet the 20x20 goal is summarized in the REDI Report’s appendix. A full description of the modeling and assumptions is available
in the UCD technical report on the REDI page on the Electric Utilities page of the GEO website (www.colorado.gov/energy).
The top line of the following graph indicates the trajectory of CO2 emissions based on the direction of Colorado’s elec- tricity sector before the legislature passed
demand-side and renewable energy goals in the past few years. The middle line shows where the Colorado electricity sec- tor is now heading, taking into account current laws and regulatory rules that prescribe renewable energy and energy efficiency outcomes. The bottom line
shows the trajectory of CO2 emissions that Colorado’s electricity sector would need to meet to reach the 20x20 goal.
As indicated, Colorado faces a CO2 emissions gap between where the elec- tricity sector’s existing policies will reach by 2020, as compared to the 20x20 goal.
The REDI Report addresses how Colo- rado’s electricity sector could close this gap and concludes that, if the sector is to meet the 20x20 goal, the following steps should be taken:
n Greatly increase investment in demand-side resources (energy efficiency, demand-side management, demand response, and conservation).
n Greatly increase investment in re- newable energy development, particularly utility-scale wind and solar generation.
n Accelerate construction of high-volt- age electric power transmission to deliver renewable energy from Colorado’s renew- able resource generation development areas to the state’s major load centers.
n Strategically use natural gas-fired power generation to provide needed new power to the grid and to integrate natu- rally variable renewable resources.
n Consider decreasing the utilization factor of coal-fired generation and/or consider early retirement of the oldest and least efficient of the state’s coal-
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fired generating stations. Meeting these challenges points to the
need not only for continual improvements within the electric power industry, but also to the need for modifications to regula- tory and policy structures. Colorado could benefit from even stronger interstate coordination among the multiple players who plan new generation and transmis- sion. The power system currently oper- ates under a smaller balancing authority area than might be desirable for the most advantageous integration of wind and solar power. The current smaller separate balancing authority areas may have the effect of increasing the cost of delivering
renewable power to Colorado customers. Without a single regional balancing au- thority area, Colorado may risk increased costs of transmitting power beyond what such prices might be under more coordi- nated transmission pricing systems.
Finally, delays associated with siting and permitting of transmission lines will hamper Colorado’s utility-scale renewable energy development unless modifications are made to the process.
Although Colorado’s electricity sector has made notable strides in recent years in the direction of meeting the 20x20 goal, further steps in that direction are offered by the report. If the sector
successfully meets the 20x20 goal, the report indicates that the state’s economic development will be bolstered by deploy- ment of clean energy infrastructure, with new jobs stemming from investments in renewable energy manufacturing.
The report suggests that Colorado stakeholders examine:
n The benefits, feasibility and possible procedures for developing a state and regional long-range transmission plan. The objectives of the plan would include traditional electric reliability needs, cost stability, and incorporation of the most cost-effective options to reduce CO2 emissions.
n The costs and benefits of a regional balancing authority area of which Colo- rado would be a part. Colorado should strengthen its engagement with neigh- boring states in relation to governance and operation of the transmission system over a multi-state area.
n The most effective means to secure robust participation from a diverse set of stakeholders to ensure that Colorado’s lands, wildlife, scenic, and other natural resources are adequately considered. Stakeholders should also consider whether it is warranted to seek additional guidance regarding the avoidance of sensitive areas.
n Whether a process should be initi- ated to determine the costs and benefits of a statewide transmission siting author- ity, to include county commissioners and other key stakeholders.
Colorado Electricity Sector Carbon Dioxide Emissions in Millions of Metric Tons
W H E R E C O L O R A D O W A S H E A D I N G
W H E R E C O L O R A D O I S H E A D I N G
P A T H T O T H E 2 0 2 0 G O A L
COLORADO CO2 EMISSIONS PROFILE SCENARIO & SENSITIVITY ANALYSES
2005 2008 2011 2014 2017 2020
45,000,000
50,000,000 M E T R I C T O N S O F C O 2
55,000,000
40,000,000
35,000,000
GAP
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This report discusses Colorado’s electric- ity sector and offers information about the challenges it may encounter as it develops plans to reduce carbon dioxide (CO2) emissions. The baseline analysis underpinning this report stems from what we call the “20x20 goal.” The goal is a reduction of CO2 emissions in Colo- rado’s electricity sector by 20 percent by 2020 from 2005 CO2 levels. Throughout the report, we pose questions and offer information intended to stimulate further interest aimed at designing sound poli- cies for a less carbon-intensive electricity sector in Colorado.
Baseline information and projections for new electric generation capacity are the results of computer simulations conducted by Dr. Saeed Barhaghi, Engineering Research Professor at the College of Engineering at the University of Colorado at Denver, under a consulting contract with the GEO. The report refers to the modeling work conducted for the project as the “UCD modeling” or “the modeling.” The GEO and the DOE did not conduct third-party verification of the modeling results. Accordingly, the report does not formally adopt the findings of the modeling as evidentiary facts. We encourage readers to review the sum- mary of the UCD modeling, located in the
appendix of this report. The full technical UCD modeling report is available on the GEO website.9
The projections used in the UCD model- ing are intended to be a starting point for analysis, recognizing that factors unknown today will undoubtedly affect where Colo- rado’s electricity sector will be in 2020. The REDI project provided guidance to the UCD contractor that the modeling should employ several key assumptions, including, but not limited to the following: n Do not assume electric generation technologies will go on line by 2020 that are not commercially-viable today. n Project energy consumption trends based on historical usage data, integrated with current regulatory policies. n Assume the regulatory and policy structure today represents the maximum that will be accomplished in a “business as usual” scenario. For example, although utilities are not prohibited from accom- plishing greater levels of energy efficiency or higher penetrations of renewable ener- gy than are currently required by law, the modeling does not assume that utilities achieve levels of efficiency and renewable energy that are greater than their current regulatory or statutory mandates. n Use conservative assumptions for fos- sil fuel prices.
n Assume that an IGCC plant will be built in Colorado before 2020. n Do not use cost adders that may result from a carbon regulatory structure.
The UCD modeling is based on three scenarios:
The first scenario, illustrated by the top line in the graph on the following page, represents CO2 emissions stemming from Colorado’s 2005 electric generation fleet and the trends for electric demand growth that were evident in 2005. We refer to this line as “Where Colorado Was Heading.” Absent policy changes in this scenario, Colorado’s electricity sector CO2 emissions would have escalated from 44 million metric tons per year (MMT/Y) in 2005 to 55 MMT/Y in 2020.
The second scenario, illustrated by the second line, represents expected CO2 emissions based on current regula- tory and statutory requirements. We refer to this line as “Where Colorado Is Heading.” This scenario anticipates the minimum generation from renewable energy as required under Colorado’s RES, the minimum demand-side management (DSM) policies as required by state law and regulatory decisions, and recently updated forecasts of electric load growth. The modeling calculated that Colorado is currently on a path to reduce annual CO2
I. The 20X20 Goal: Reducing Carbon Dioxide in Colorado’s Electricity Sector by 20 Percent by 2020 from 2005 CO2 Levels
The modeling results
of renewable power and
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emissions by 7.5 MMT/Y in 2020 from the levels they otherwise would have been if there were no policy changes. These CO2 reductions from the first scenario are a direct result of Colorado’s RES and mandated targets for demand-side man- agement (DSM). Credit for these initia- tives is widely attributed to unparalleled cooperation and leadership among a variety of entities, including Governor Rit- ter, the Colorado Legislature, the Public Utilities Commission (“the Commission” or “the PUC”), electric and gas utilities, and engaged Colorado citizens. We note that Public Service Company of Colorado (“PSCo”),10 Tri-State Generation and Transmission Association (“Tri-State”),11 and many other Colorado utilities, have adopted CO2 reduction policies that point the way forward to address the top- ics discussed in this report.
The third scenario, illustrated by the bottom line of the graph, represents the CO2 emissions pathway that the state’s electricity sector must reach if it is to attain the 20x20 goal. On the graph, we refer to this as the “Path to the 20x20 Goal.” When existing legislative and regu- latory measures are taken and projected into the future assuming no new policy changes, electricity sector CO2 reduc- tions will miss the 20x20 target by 11.4 MMT/Y. In other words, the policies cur- rently in force today will take Colorado’s electricity sector 40 percent towards the 20x20 reduction goal.
To bridge the remaining gap will re- quire increased demand-side measures, utility-scale renewable energy, new high- voltage transmission, more natural gas generation, and initiatives that address CO2 emissions from the state’s oldest
and least-efficient fossil plants. An increase in the necessary levels of
high-voltage transmission development, which is a primary focus of this report, is based on projected levels of required generation to meet the 20x20 goal. All es- timates of required generation are based on assumptions of the growth in electric power demand. With that approach in mind, the modeling results indicate that closing the gap will involve a substantial increase in the use of renewable power and natural gas generation.
Demand-side measures also will play a critical role in keeping CO2 emissions low. The UCD modeling used an assump- tion of efficiency policies to keep annual demand growth near the current annual 1.4 percent growth level and also allowed the demand to return to its historical an- nual growth rate of 2 percent.
PSCo’s most recent Annual Progress Report Regarding Electric Resource Plan- ning report to the PUC provides detailed energy sales forecasts.12 The following im- portant statistics are found in the report:
“Residential sales have increased an average of 1.6 percent per year over the past five years. Customer growth is expected to remain at or below levels seen since 2003, averaging 1.2 percent per year. Weather normalized use per customer has increased only 0.1 percent per year over the past five years, and is expected to decline by —0.4 percent per year through 2015, primarily due to new federal standards for lighting and appliance efficiency. As a result, residen- tial sales are forecast to increase only 0.5 percent per year on average through 2015. Commercial and industrial sales are projected to increase at an average annual rate of 1.5 percent through 2015, following average growth of 2.1 percent per year during the past five years. The current recession, including significant impacts on the mining and natural gas industries, resulted in slower growth. During the past five years total retail sales have increased 1.9 percent. Slower residential and commercial and industrial sales growth will result in lower growth of 1.2 percent through 2015.”
Colorado Electricity Sector Carbon Dioxide Emissions in Millions of Metric Tons
W H E R E C O L O R A D O W A S H E A D I N G
W H E R E C O L O R A D O I S H E A D I N G
P A T H T O T H E 2 0 2 0 G O A L
COLORADO CO2 EMISSIONS PROFILE SCENARIO & SENSITIVITY ANALYSES
2005 2008 2011 2014 2017 2020
45,000,000
50,000,000 M E T R I C T O N S O F C O 2
55,000,000
40,000,000
35,000,000
GAP
12
Aggressive demand-side measures would reduce the growth in demand, resulting in cost-effective savings in the electricity sector. We note that Colorado has made substantial progress recently in energy efficiency. The American Council for an Energy Efficient Economy (ACEEE) reports that Colorado jumped to 16th from 24th among the 50 states in their 2009 State Energy Efficiency Scorecard. 13 We note that the ACEEE’s scoring includes factors in addition to utility-sponsored demand side manage- ment programs.
For the purposes of this report, however, both generation and efficiency estimates are conservatively calculated based on historical energy use trends and the assumption that utilities will treat cur- rent efficiency requirements of state laws and PUC regulations as a ceiling. These factors may well change. The modeling does not assume that these changes will occur, however.
As was determined in the SB07-091 Report,14 the most potentially productive large-scale wind and solar locations are in areas where existing transmission is inad- equate to deliver the additional renewable power necessary to meet a 20x20 goal. As a result, Colorado is encouraged to focus increased attention on expanding
and upgrading its high-voltage transmis- sion infrastructure. Given the benefit of no fuel costs over a time frame of de- cades, minimizing the impact on electric customers suggests that utilities should build new high-voltage transmission lines to connect those Colorado areas with the highest concentrations of least-cost re- newable potential to the areas of highest electric demand. Achieving these results assumes a continual improvement in the approach to grid planning and operation.
What is the basis for the proposed 20x20 goal in the REDI Report? The basis for the 20x20 goal is a grow- ing recognition that Colorado’s elec- tricity sector is preparing for a carbon- constrained financial, regulatory, and operational environment. Preparing for operating in a carbon-constrained environment has become increasingly
important, particularly given recent congressional indicators and activities,15 at the U.S. Environmental Protection Agency in connection with their endan- germent finding,16 at the Securities and Exchange Commission,17 and elsewhere. We adopted the 20x20 goal as a base- line condition to conduct an analysis to determine a proposed pathway for Colorado’s electricity system portfolio in 2020, recognizing that utilities may exceed existing requirements and that technology will likely undergo substan- tial changes in cost and availability. These inherently unknown future factors will obviously affect conclusions of our analysis that are grounded in current knowledge.
Accordingly, the REDI Report is analytical rather than visionary. The UCD modeling work assumes that Colorado’s
utilities will follow historical trends within known legal and regulatory requirements. As policies continue to change and tech- nology advances, the modeling analysis will be outdated, and utilities and others undoubtedly will produce new analyses. As such, the report should be considered a living document aimed at providing information and analysis with the goal of adding to public discussion. We empha- size that the authors do not claim that the proposed pathways are certain, nor do they claim that proposed pathways should be adopted as policy for renew- able energy and transmission develop- ment in Colorado.
What is Colorado’s CO2 emission pro- file, and how much is attributable to the electricity sector? In November 2007 Governor Ritter issued the Colorado Climate Action Plan (CAP), noting the importance of achieving climate stability to key Colorado industries, such as agriculture and tourism.18 A graph on page nine of the CAP is provided on the previous page. It shows that electricity consump- tion represents 36 percent of Colorado’s CO2 levels. Addressing the challenges in Colorado’s electricity sector will greatly help meet the broader CAP goals, namely achieving economy-wide CO2 emission reductions.
Colorado CO2 Emissions by Sector
Source: Colorado Climate Action Plan
13
Why is transmission so important in how the electric power system operates? Transmission is a critical element in an interconnected electric power system, which includes generators, transmis- sion lines, substations, distribution lines, and customers. Some have de- scribed the North America power sys- tem as the greatest engineering accom- plishment of the past 100 years. The U.S. electric power industry represents more than $1 trillion in asset value, with 950,000 MW of generating capac- ity and 200,000 miles of transmission lines. There is no larger collection of assets in any system, except perhaps the petrochemical complex. Colorado is home to dozens of generating sta- tions that equal more than 13,000 MW of capacity, and thousands of miles of transmission power lines of 115 kilo- volts and higher voltage. The UCD work conducted for the REDI Project mod- eled for the base year 2005 included 152 generating units in Colorado with gen- eration capacity of more than 11,200 MW owned by utilities and independent power producers. Since 2005, Colorado has added or will soon add nearly 3,000 MW of new generating capacity to meet the growing demand and a changing resource mix.
Transmission provides a critical link between generators and electric custom- ers. A National Council on Electricity Policy primer on transmission19 identified four major reasons why transmission is so important. According to the NCEP report, broadly, a strong transmission system: 1) Improves the reliability and security of the electric power system, upon which most of the economy and way of life we enjoy depends, 2) Gives electricity customers flexibility to diversify the mix of fuels that produces their electricity by giving them access to power plants outside of their immediate vicinity, 3) Improves the cost structure of the entire industry by giving low-cost power plants access to high-cost power mar- kets, and 4) Enables competition among power plants by giving more plants access to more markets.
The challenge of operating a robust transmission system is complex, since it is difficult to economically store any significant amount of electricity, and the supply of electricity must always match the demand at any given time. To achieve a consistently high level of reliability and cost effectiveness, the NCEP report de-
scribed the following major requirements of the electric utility system:
n Balance power generation and demand continuously. As loads come on and off (as weather changes or as a result of, for instance, most electric equipment being turned on at the beginning and end of a work day), power generation must continuously and accurately match that demand. A large mismatch of demand and supply can damage power genera- tion facilities. The mismatch causes, at a minimum, a low voltage condition in some parts of the grid (commonly re- ferred to as brownouts). At a maximum, the mismatch could be so severe that it causes a failure of larger segments of the power grid requiring a rolling blackout if load is intentionally shed for a period of time first in one place, then another.
n Monitor flows over the transmis- sion system to ensure that thermal (heating) limits are not exceeded. Electricity flowing over power distribution and transmission facilities causes those facilities (power lines, substations and the like) to heat as do high ambient air temperatures. When the power lines heat they can sag, and if they make contact with a tree that was not trimmed, for ex- ample, it could cause a short circuit. The power system must operate within the
constraints of its thermal limits — opera- tors must be sure not to send so much power over the lines that they fail and cause brownouts or cascading blackouts, where loss of load in one area causes adjacent areas to trip and crash.
n Operate the system so that it remains reliable. Transmission system operators are required by federal rules to operate their systems to ensure that if any single line, substation, or generating unit in the system were to fail, the rest of the system could accommodate the loss instantaneously without interruption. Systems must operate to meet frequency targets or face mandatory fines. Meeting this national reliability standard is a way to continually ensure that the transmis- sion system operators can plan for the unexpected loss of a major part of the system and operate so they can main- tain grid reliability and service quality for customers.
n Plan, design, and maintain the system to operate reliably. Short-term transmission planning addresses needs — often based on weather and expected power loads — for the following days or week. Long-term planning focuses on a multi-year effort to forecast demand on the transmission and generation system, plan for the mix of generation to supply
The REDI Report is analytical rather than visionary. The UCD modeling
work assumes that Colorado’s utilities will follow historical trends within
known legal and regulatory requirements.
14
the forecasted loads, and acquire the gen- erators and transmission to bring them to loads. Such long-term planning typi- cally extends for a minimum of 10 years, but often will extend to 15 to 20 years.
When proper safeguards are not in place, a transmission system failure can cascade quickly across multiple states, although physical breakpoints between three separate U.S. interconnections —Eastern, Western, and Texas — isolate such failures to one of the three regions. It is important to note that very few major system failures have occurred during U.S. history. Although they are rare, major fail- ures have occurred, however. The most notable failures were the 1965 blackout in New England and the 2003 blackout in the Midwest and parts of the East Coast and Canada. Minor grid disturbances can become large grid events. On August 10, 1996, for example, a massive voltage col- lapse caused the largest blackout in the history of the Western power grid.20 The blackout caused a loss of load of 30,000 MW, and the entire Western Intercon- nection was broken into five pieces: the amount of power lost was equivalent to 15 cities roughly the size of Denver.
Another critical point relates to the importance of the transmission system for renewable energy. Transmission connects
widespread use of renewable energy in the United States. If developed, the Tres Amigas SuperStation21 would help route energy from isolated wind and solar installations to urban centers and other places that consume the most power. Tres Amigas would build a triangular pathway of underground superconduc- tor pipelines, combined with AC-DC-AC converters to synchronize the flow of power between the interconnections, allowing electricity transfer from grid to grid. Construction could begin in 2011 or 2012, and the hub could be operat- ing in 2013 or 2014. The 3-feet diameter pipelines contain hair-thin ceramic fibers (developed by American Superconductor) that can carry enough electricity to power 2.5 million homes.
What is the history of the Rocky Moun- tain region’s electric generation and fuel type? The chart above shows the growth in electric generating stations in the Rocky Mountain region from 1905 to the pres- ent. Relatively few megawatts of power were added in the region until the 1950s, due to low electric demand and low per capita use by a much smaller popula- tion. Following World War II the region experienced a population boom. To keep pace with the demand, major coal and
resources to markets (“loads”), and, in general, the best U.S. utility-scale renew- able energy resources are far from many population load centers. The map above indicates two important points. First, the nation’s wind resources generally are far from the load centers. Second, the nation has three interconnection grids that are not synchronized, and historically could not be.
Not shown on the map are six AC-DC- AC ties connecting the Western Intercon- nection and the Eastern Interconnection in the United States and one additional AC-DC-AC tie in Canada. The other two U.S. ties are Public Service Company of New Mexico’s Blackwater, New Mexico
tie and the El Paso Electric and Texas- New Mexico Power Company’s Artesia, New Mexico tie. PSCo owns the tie in Lamar, Colorado.
Plans have been announced to poten- tially ease the isolation of the Western, Texas, and Eastern Interconnections. A proposal has been made to develop a 22-square-mile in eastern New Mexico at Clovis, near the Texas border. Clo- vis was chosen for its proximity to the conjunction of the nation’s three power grids. The approximate $1 billion project would allow energy to flow more freely across the nation’s three massive power grids. It has the potential to allow more
Three National Interconnections; Load Centers; Wind Resource
Wind Resource
Load Centers
15
hydroelectric plants were built during the 1950s. Beginning about 1970 the goal of siting new hydroelectric plants became more challenging, in part due to lack of sites and due to environmental constraints. From the 1970s through the mid-1980s, the major generating addi- tions were coal-fired plants.
Not shown on the graph what was PSCo’s Ft. St. Vrain 330 MW high-tem- perature gas-cooled nuclear reactor. The plant near Greeley, Colo. came on line in the mid-1970s, but was decommissioned in 1989 due to major cost overruns and operational considerations. With the exception of Ft. St. Vrain, no nuclear
reactors have been built in the Rocky Mountain region, primarily due to their high costs.
With the advent of gas-fired com- bustion turbines in the mid-1980s and policies that encouraged competition in the wholesale markets, utilities turned primarily to natural gas for intermedi- ate and peaking resources. Natural gas prices were high in the late 1970s and early 1980s, receded in the mid-1980s, then spiked in the early 2000s. As is evi- dent in the graph, Rocky Mountain region utilities have, for the most part, favored gas-fired generation over the past fifteen years due to its lower comparative capital
costs, easier siting, and because major long-distance transmission investments are not necessary.
The graph indicates a marked increase in the number of non-hydro renewables in operation in recent years, most of which have been wind power. Due to con- cerns about CO2 and as a result of likely cost-reductions as the technology scales, it is widely expected that the number of solar power plants online in the region during the next decade will substantially increase.
A 750 MW coal-fired generating unit (Comanche 3)22 in Pueblo, Colo. is expected to come online before the end
of 2009 or early 2010. New coal-fired generating stations may be limited due to uncertainties surrounding CO2 regula- tion. The generating stations that come online in the next decade will be deter- mined by utility and regulator responses to emerging challenges. These challenges include, but are not limited to financing, permitting, environmental regulation, and available transmission capability.
How does population growth affect the demand for electric power? Per capita electric consumption is in- creasing, and, as a result, so are overall demands on both electric generation and transmission. Colorado’s population has
1910
18- Vintage- 4 column
Generation Vintage in the Rocky Mountain Region by Fuel Type
Source: R.W. Beck/Ventyx Velocity Suite
16
steadily increased since the end of World War II: the growth rate has fluctuated in concert with population and the econo- my, but has generally increased during the past 20 years. This population growth translates directly into greater need for electric power and for more aggressive demand-side measures.
Various historical national demographic trends indicate that Colorado’s population growth is expected to continue. According to Colorado’s State Demography Office, in 1990, 3.3 million people lived in Colorado: by 2009, the number had reached 5.1 mil- lion, an increase of more than 55 percent. Assuming an approximate 1.5 percent
annual growth rate, the state’s population is expected to increase by an additional 21 percent to 6.3 million by 2020. A July 2009 report by the Colorado Water Conserva- tion Board23 concludes that Colorado’s current water use will likely almost triple by 2050 due to a growing population and economy and environmental needs. The growing water requirements form a nexus with strategic electric power questions facing Colorado, since traditional electric generating technologies use large volumes of water.24 The Water Conservation Board study notes that the state’s population is expected to double from 5 million to 10 million between 2010 and 2050.
Colorado’s electric power usage has grown steadily as well. In 1990, total Colorado residential, commercial and industrial electric consumption was almost 31,000 gigawatt-hours (GWh). By 2007, DOE Energy Information Admin- istration data show that consumption had increased by 67 percent, to more than 51,000 GWh. Given the increasing electrification of an energy-hungry digital economy, typified by the growth in plug loads (such as computers, photocopi- ers in commercial buildings) and the increased penetration of residential air conditioning, the electricity consumption growth outpaced that of the population
growth rate. Colorado could be worse off in this regard were it not for the fact that less than one-fifth of the state’s house- holds use electricity as their main energy source for home heating.
According to PSCo, the company’s average growth in electric sales from 1997- 2008 was 2.6 percent per year. With more ambitious energy efficiency programs, and because of the slow-down in the economy, PSCo has projected the future electric growth rate to be less than it has been historically.25 Of course, this can change.
Steady national growth in electric consumption is evident in the graph above, produced by the DOE’s Energy Information Administration (EIA).26 The graph indicates retail electric sales in the United States, by sector, from 1949 through 2008.
The graph on the following page provides an historical depiction and future forecast for electric load for the entire state. The forecast was produced in a report entitled Colorado’s Electricity Future a Detailed Look at the State’s Electricity Needs and Electricity’s Economic Impacts27 published in September 2006 by the Colorado Energy Forum, an organiza- tion sponsored by Colorado’s electric utility industry. That comprehensive study antici- pated continued growth in electricity demand during the coming years.
Although the current recession has dampened demand for electricity, it is important to monitor the full economic cycle, which may well include increased demand in future decades. The June 2009 Short-Term Energy Outlook from the DOE’s Energy Information Administration (EIA)28 provides this data:
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Electricity Retail Sales by Sector, 1949-2008
Industrial
Commercial
Residential
4,731,787
5,218,144
5,737,305
6,287,021
17
“During the first quarter of 2009, total consumption of electricity fell by an estimated 3 percent compared to the same period last year primarily because of weak industrial consumption. Growth in residential retail sales during the second half of this year is expected to slightly offset continued declines in industrial electric- ity sales. Total consumption is projected to fall by 1.8 percent for the entire year of 2009 and then rise by 1.2 percent in 2010. Total U.S. electricity consumption fell by 4.4 percent during the first half of the year compared with the same period in 2008, primarily because of the effect of the economic downturn on industrial electricity sales. The expected year-over-year decline in total consumption during the second half of 2009 is smaller, a 2.3 percent decline, as residential sales begin to recover.”
The combination of population growth and the growth in electricity demand suggests a commensurate expansion and balancing of efficiency, generating capacity and transmis- sion. The challenge Colorado faces is to make cost-effective and environ- mentally responsible decisions, while improving the historically high level of electric reliability in the state. The UCD modeling findings show that new renewable energy development and
increased electric transmission capacity — in addition to continued ambitious efforts to reduce demand and increase deployment of demand-side resources — will be critical to meeting new load growth using the most cost-effective, reliable, and environmentally meth- ods. According to REDI’s generation and transmission baseline consultant (Navarro-E2MG),29 as a result of load growth forecast and the PUC’s Electric Resource Planning process, about 5,570 MW of new capacity is planned to be installed in the next six years: 2,369 MW will be categorized as must run units, 3,070 MW as base units, and 26 MW as peaking units.
Assuming an economic recovery, and if Colorado does not adopt more aggres- sive statewide electric efficiency goals, the state will face a difficult challenge in its attempt to achieve zero, or near zero, load growth. Several factors potentially stand in the way of efforts to decrease load growth: n More people are moving into Colorado and require new electric infrastructure to meet their demands. n Population growth is accompanied by growth in residential electricity consumption due to additional electricity-using equipment. n The amount of commercial and
industrial electricity consumed per dollar of real gross domestic product (GDP) is increasing. n Energy efficiency in the commercial and industrial sectors has improved since 2003, but not dramatically.
How can demand-side measures help meet the 20x20 goal? In this report, electric power conserva- tion, energy efficiency, demand-side management, demand response, and distributed generation are defined as “demand-side measures.” n Conservation refers to behavioral avoidance of unnecessary usage. n Energy efficiency refers to using less energy to do the same job. n Demand-side management (DSM) re- fers to managing the timing and amount of energy use. Those electric customers
who avail themselves of utility-sponsored demand-side measures will see lower utility bills. n Demand response (DR) refers to changing the timing, often using auto- mated controls (or “smart grid” applica- tions), when customers use energy. n Distributed generation (DG) refers to on site generation, typically owned and run by homeowners or businesses.
Under most circumstances, demand- side measures are cost-effective approaches that will play an increasingly important role in the portfolio of resources Colorado will need to meet its future electric power needs. These demand-side measures are consid- ered an important component of the port- folio that includes a broad mix of supply- side measures that are necessary to meet Colorado’s electric power requirements.
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Peak High
0 0000 000
Projected Increase in Peak Hour Generation of Colorado Electric Power, 1996-2025
Source: Colorado Energy Forum
18
What is distributed generation, and how is that concept emerging in Colorado? Distributed generation (DG) consists of small-scale electric generators typically located at or near where customers use electricity. Small-scale rooftop or ground-mounted solar photovoltaics (PV) installations are examples. Other technologies such as combined heat and power, distributed wind power, and diesel powered generators also are typically considered to be DG. As of the writing of this report, Colorado has a to- tal of approximately 45 MW of installed PV. By comparison, Colorado had less than 1 MW of installed PV in 2005. An 8.3 MW PV plant installed near Ala- mosa provides power to PSCo. Several other 1 MW and larger PV projects are installed in Colorado and many more are planned. Should the costs of PV and DG continue to decline and supportive policies substantially expand, DG in Colorado has the potential for exponen- tial growth.
A significant development in the growth of DG in Colorado is now ex- pected, given PSCo’s announcement that the company is adding nearly 260 MW of on-site solar power generation to its 2010 Renewable Energy Standard Compliance Plan.30 The expanded PV goals are part of
PSCo’s plan to meet Colorado’s RES over the next decade: it includes previously announced targets of 700 MW of new wind power and 350 MW of utility-scale solar power plants. Under state renew- able energy requirements, PSCo could have complied with the RES with just 85 MW of PV.
Can demand-side measures mitigate or eliminate the need for new central power stations and new transmission? The answer to this question could be yes, if customer behavior were more dependable, if loads were under greater utility control, or if Colorado experienced no load growth. Colorado’s population continues to grow, however, as does the per capita consumption of electric power. The recent economic recession, coupled with new efficiency policies implemented by PUC-regulated investor-owned utilities (IOUs), have reduced load growth in certain utility service territories. Should
economic activity in Colorado rebound, the result could include a return of electric demand to the historic growth levels of 2 percent or more per year. With these factors in mind, a pathway going forward would balance rapid deployment of demand-side measures (particularly aimed at lowering expensive peak use); energy conservation across all hours of consumption; and investment in new utility-scale renewable generation, gas-fired generation, and high-voltage transmission resources.
The data shown in the graph above in- dicate directions for achievable improve- ments in electricity efficiency: we have the opportunity to use less energy to produce $1 of economic output, and less energy needed to keep Coloradoans comfortable. Doing both not only will reduce CO2 emissions, but also will support state prosperity and enhance quality of life.
As with all other strategies, some
demand-side options are more cost-ef- fective than others. These resources take their place on the customer’s side of the meter, requiring financial inputs by the customer, and if determined as policy, by the utility. A report by the Southwest En- ergy Efficiency Project, Recent Innovations in Financing for Clean Energy31 provides an update on methods being used to help finance many of these measures.
The least expensive of these demand- side measures generally are more cost- effective than the least-expensive new central generation and transmission options because demand-side measures involve less capital cost. Demand-side options typically present less risk be- cause they tend to be small and modu- lar, rather than large and centralized. As utilities evaluate these measures they take into consideration several factors, including operational certainty, durabil- ity, and lost revenue.
The recent trend in Colorado toward greater utility emphasis on sponsoring demand-side options is encouraging: far greater emphasis on demand-side solutions will mitigate the need for new supply-side resources, possibly including transmission. New efficiency opportuni- ties also have resulted from advanced federal appliance efficiency standards,
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Colorado Residential and Non-Residential Electric Consumption Trends
Source: National Renewable Energy Laboratory
19
and from improved efficiency and reliabil- ity of these technologies. A goal of zero percent per capita load growth could be achievable, given a robust investment in demand-side measures, as demonstrated in the chart to the right comparing Cali- fornia to the United States.
For this analysis, the UCD model assumed that Colorado’s existing demand-side measure policies will remain unchanged through the year 2020. This is not to assume that no change in existing policies is a preferred scenario. Continued policy changes such as those initiated the Governor, the Colorado General Assembly and regulators in the past several years are to be encouraged.32 The primary thrust of these demand-side policies, to date, has been applicable to IOUs. New com- mitments to energy efficiency and renew- able energy also have been achieved by innovative approaches taken by the IOUs. We note an important contribution to the topic of demand-side measures has been produced by the Staff of the PUC in a 39-page report, Energy Efficiency and Colo- rado Utilities: How Far We’ve Come; How Far We Need to Go.33 It documents the benefits that would be derived as a result of greater commitments and coordination among all Colorado utilities, the PUC, the GEO, and various other stakeholders.
A proposed selection process to help balance these needs is contained in the Electric Power Research Institute’s report, The Power to Reduce CO2 Emissions: The Full Report.34 An additional document to help analyze the potential for alternatives to transmission is available in the Sep- tember 2009 National Council on Elec- tricity Policy report, Updating the Electric Grid: An Introduction to Non-Transmission Alternatives for Policymakers.35 The report provides detailed information regard- ing five broad policy options including: end-use efficiency, end-user demand response, generation alternatives (includ- ing distributed generation), transmission system capability and efficiency improve- ments within existing corridors, and developing storage technologies, such as batteries and electric and plug-in hybrid electric vehicles.
The September 2009 Northwest Power and Conservation Council report,
Draft 6th Power Plan36 found that in each of its power plans, substantial amounts of conservation to be cheaper and more sustainable than many forms of additional electric-generating capa- bility. The Plan found enough conserva- tion to be available and cost-effective to meet the load growth of the Northwest region for the next 20 years. The Coun- cil states that “If developed aggressive- ly, this conservation, combined with the region’s past successful development of energy efficiency could constitute the future equivalent of the regional hydroelectric system; a river of energy efficiency that will complement and protect the regional heritage of a clean and affordable power supply. At the same time, the region cannot stand still in maintaining and improving the reli- ability of its power system. Investments in additional transmission capability and improved operational agreements
are important for the region, both to access growing site-based renewable energy and to better integrate it into the power system.”
Today, a vibrant centralized utility system is essential to Colorado’s electric reliability. Even under the most ambitious demand-side scenarios, the intercon- nected system will continue to help meet the needs of a growing decentralized paradigm. A harmonious combination of demand-side resources and a careful selection of supply-sources will most ef- fectively meet the state’s energy, econom- ic, and environmental goals.
How can utility-scale renewable resourc- es help meet the 20x20 goal?
A low-carbon Colorado electricity sector will require changing the balance of fuels in the state’s electric generation portfo- lio. The change will result in use of fewer high-carbon fuels such as coal, a greater fraction of lower-carbon fuels such as natural gas to displace the higher carbon generation, and more zero or near-zero carbon sources — including demand-side measures, wind, solar, geothermal, and hy- dropower. Even if existing energy efficiency goals are met, a substantial increase in utility-scale renewable generation and natural gas generation will be required, as will new high-voltage transmission.
Electricity Sales Per Capita per Year
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California
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The utility-scale renewable industry has grown considerably in the past few years, and is well-positioned to grow even more. Colorado has much to gain in the process. According to Colorado-based Interwest Energy Alliance, a trade and advocacy group, Colorado currently has 12 wind farms, most of which have power purchase agreements with PSCo. Togeth- er, these wind turbines produce enough power for approximately 400,000 homes. The Interwest Energy Alliance reports that more than 30 wind farms are installed in various sizes in Arizona, Wyoming, New Mexico, Utah, and Colorado.
Colorado’s utility-scale renewable energy industry is robust, as evidenced by the industry’s response to a request for proposal (RFP) issued by PSCo’s 2009 All Source Solicitation: PSCo received 49 wind bids totaling 10,800 MW; 28 bids for solar (photovoltaics and thermal) totaling 2,150 MW; eight bids for solar (PV and thermal with storage or gas backup) totaling 1,250 MW; and three non-solar renewable energy bids totaling 1,150 MW. Most of these bids came from projects located in Colorado. Under its most recent resource plan, PSCo will add nearly 1,000 MW of wind and solar to its system, and it will retire older coal-fired power plants (Units 1 and 2 at the Cameo
Station near Grand Junction by the end of 2010, and Units 3 and 4 at the Arapahoe Station in south Denver by 2014), totaling 229 MW.
As of September 2009, PSCo receives output generated by 1,232 MW of name- plate capacity from 10 wind farms located within Colorado and 25 MW from one wind farm in Wyoming. PSCo operates on the basis of regulatory and corporate commitments that continue to increase the company’s renewable energy pur- chases as economically and operationally feasible. Although rural electric coopera- tives, aggregated for generation purposes primarily by Tri-State, and municipal utilities have similar, but smaller renew- able energy standard obligations, they, too, see opportunities to expand their commitment to develop more utility-scale renewable energy.
Further evidence of Colorado’s continued utility-scale renewable energy growth was the July 6, 2009 announce- ment by Tri-State of its plans to purchase the output of 51 MW of wind power from Duke Energy Generation Services. This agreement was made possible because Tri-State had a limited amount of capacity on its constrained transmission system. The wind farm, to be built near Burling- ton, Colo., will supply enough electricity
to supply 14,000 households served by distribution co-ops within the Tri-State network. Duke Energy will build the project and sell the power to Tri-State for 20 years. The project, consisting of 34 turbines on 6,000 acres, is expected to be completed by the end of 2010. About 150 people will be employed to build the project and four to eight full-time technicians will maintain it. Duke Energy reported that costs were “north of $100 million.”
The SB07-91 Report identified Colo- rado GDAs that have the best potential for producing low-cost wind power and central-station solar power. Large-scale wind plants have proven to be commer- cially and economically viable. Large-scale wind developments on the Colorado grid act as a hedge against high natural gas prices. Photovoltaic plants show steadily decreasing costs that could potentially bring them to “grid parity” costs in the next decade. These plants are included in the state’s renewable energy stan- dard, established to enable further cost decreases through more widespread deployment. Photovoltaics and concen- trated solar power (CSP) plants can also serve as a hedge against high natural gas prices. In addition, strategically located smaller renewable power plants, although
they have higher capital costs than larger ones, could reinforce local reliability, reduce or delay transmission upgrades, and help diversify the system. This would be especially applicable in areas on Colo- rado’s Western Slope where building new transmission is more challenging.
How can natural gas-fired generating plants help meet the 20x20 goal? According to the Independent Petroleum Association of the Mountain States, Colorado is the sixth largest producer of natural gas in the United States. Seven of the nation’s 100 largest natural gas fields are found in Colorado. Colorado is responsible for more than one-fourth of all coalbed methane produced in the United States. Coalbed methane output accounts for about one-half of Colorado’s natural gas production.
On many occasions Governor Ritter has noted that he considers natural gas to be an essential and permanent part of the New Energy Economy. This report recognizes that natural gas is not a bridge fuel, and it is not a transition fuel. Natural gas is a mission-critical fuel when considering reductions in CO2 emissions and the need to integrate utility-scale re- newable energy. Natural gas-fired electric generation has the important attribute of being a flexible resource that emits half
As of September 2009, PSCo receives output generated by 1,232 MW of
nameplate capacity from 10 wind farms located within Colorado and 25 MW
from one wind farm in Wyoming.
21
as much CO2 per MWH as coal-fired generation.37 The North American Electric Reliability Corporation forecasts natural gas generation capacity will increase by 38% over the next decade, while coal- fired generation, which currently provides about half of the power in the U.S., will only grow by 6%.
A recent indicator of the increase in gas-fired generation in Colorado is the announcement by a Black Hills Energy subsidiary to build a 200 MW plant with the potential for a minimum of 100 MW expansion of natural-gas fired generation beyond that. The power will be distrib- uted to nearly 100,000 of Black Hills Energy’s utility customers in its service territory, which encompasses Pueblo, Canon City, and Rocky Ford, Colorado.
In Minnesota, Xcel Energy has com- pleted a $1 billion voluntary project—the Metro Emissions Reduction Project— which included conversion of two of its older pulverized coal generation plants to gas combined-cycle technology. As a result, sulfur dioxide and nitrous oxide emissions from the plants were reduced by more than 95 percent, and CO2 emis- sions were cut by roughly 40 percent.
Electric utilities rely on gas-fired gen- eration to reach a moment-to-moment balance between system demand and
total system generation, which is es- sential to preventing system failure. Coal-fired generation (and nuclear plants elsewhere in the nation) lacks this ability to quickly increase or decrease produc- tion. Although wind and solar output can change quickly, modern gas-fired generat- ing plants are flexible enough to man- age such changes and maintain overall system reliability.
Integrating more renewable power reli- ably and cost effectively involves various approaches. It is important to re-examine how natural gas is dispatched, transport- ed, and stored: how gas-fired generating units are specified for new equipment to be added; and how both new units and existing generators are dispatched. The Colorado electricity sector has a need for more output from natural gas plants. The UCD modeling quantifies the need for a substantial increase in natural gas generation on Colorado’s electric power system to provide injection of new power to meet load growth and to provide nec- essary firming and integration of renew- able resource generation.
State-of-the-art forecasting can enable efficient co-scheduling of wind, solar and natural gas power. These forecast- ing techniques will make it possible to maximize every megawatt of renewable
capacity, minimize the effects on reliabil- ity, and reduce costs to electric custom- ers. A strong synergy between variable renewable resources and dispatchable natural gas plants is described in greater detail in this report.
What is the role of coal-fired generation regarding the 20x20 goal? Coal-fired generation has played a major role in providing affordable, reliable power to Colorado’s electric customers for many years. Coal will likely will have a continued, but perhaps diminishing, role as an im- portant source of baseload power genera- tion. Coal-fired plants account for about seven-tenths of the state’s electric power generation.
Colorado produces coal from both underground and surface mines, primar- ily in Colorado’s western basins. Large quantities of coal are shipped in and out of the state by rail. Colorado’s major coal mining companies are the Foidel Creek Mine/Twentymile Coal Company, Elk Creek Mine/Oxbow Mining, Colowyo Mine/Colowyo Coal Company, and West Elk Mine/Mountain Coal Company. Colorado uses about one-fourth of its coal output and transports the remainder to markets throughout the United States. Colorado brings in large quantities of coal by rail, primarily from the Powder River
Basin in Wyoming, to supplement local production for Colorado electric power generation.
The UCD modeling made the conserva- tive assumption that all of Colorado’s ex- isting coal-fired generating stations would continue to generate electricity through 2020 before being retired in later years. The exception to this assumption is the planned retirement of 229 MW of PSCo- owned generation, approved by the PUC. The UCD modeling assumes that 750 MW of new coal-fired generation from the third unit at the Comanche power plant in Pueblo would come online in late 2009.
The modeling also assumes that a new coal-fired integrated gasification combined cycle (IGCC) plant would come online in 2016. This assumption is based on PSCo’s filing in the company’s November 2007 Electric Resource Plan (ERP). However, PSCo has not yet made a final decision to build an IGCC and no ap- plication to build it has been filed with the PUC. PSCo has modeled an IGCC plant as a placeholder in 2016, which is beyond the resource acquisition period in the November 2007 plan. In addition, more suggested coal retirements may be made to the PUC in the next ERP cycle to be filed by October 2010, and it is possible that the 2016 IGCC plant may be delayed.
Natural gas is not a bridge fuel, and it is not a transition fuel. Natural
gas is a mission-critical fuel when considering reductions in CO2 emis-
sions and the need to integrate utility-scale renewable energy.
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General Electric and British Petroleum recently announced a plan to jointly build a 250 MW IGCC plant designed to capture and store 90 percent of CO2 emissions. The plant will be located near Bakersfield, California. It is designed to reduce sulfur dioxide, nitrous oxide, mercury and particulates, and will oper- ate with 30 percent less water needs than conventional coal plants.
Should Colorado decide to implement the 20x20 goal, it is unlikely that new coal-fired generation would be added to the energy mix unless the plants contain major advances in carbon capture and storage (CCS).38 Although often halting and fragmented, CCS efforts have been under way for some time. However, because the technology is not yet com- mercially available, and because the costs remain high, CCS is not a part of the UCD modeling. CCS could, however, be a “game changer,” and is addressed later in this report.
In one modeling run, the UCD research analyzed the effects of de-rating the output of coal-fired generation to determine the impact on reducing CO2 emissions. For purposes of this analysis, the modeling assumed the typical utilization rate of coal- fired generation in the Rocky Mountain region at 85 percent. The model ran one
scenario in which the same coal units in Colorado’s fleet operate at a 65 percent utilization rate by 2020.
Although another modeling approach could have been constructed that would assume early retirements of specific coal units, the UCD modeling did not do so. The modeling also did not include co- firing coal-fired generating stations, which is another option to reduce CO2 emis- sions. Sufficient resources were not avail- able in the REDI Project to model these two options. Studies of these two topics are warranted to supplement the model- ing conducted by UCD on reducing the utilization rate of coal-fired generation.
The UCD modeling concludes that the largest portion of the state’s electric energy requirements and capacity needs to 2020 will be met by an integrated com- bination of utility-scale renewable genera- tion, increased natural gas generation, and derating of coal-fired generating stations.
What policy and other steps have been taken in the past few years to move toward the 20x20 goal? Many positive steps are apparent, particu- larly with regard to utility-scale renew- able energy and high-voltage transmis- sion development policies. In addition, significant policies have been enacted and practices have been implemented
to encourage greater use of demand- side resources. A narrative of the policy developments surrounding demand-side resources is contained in the SB07-91 Report and the PUC Staff report on energy efficiency referenced earlier.
Colorado’s renewable resource devel- opment has made significant strides dur- ing the past few years. In 2000, Colorado had these resources on line: 1,149 MW of hydroelectric capacity; 51 MW of wind capacity; and 7 MW of biomass gas capac- ity. By late 2009, Colorado had 1,241 MW of wind power on line, on par with the state’s 1,227 MW of hydropower. Colorado now ranks eighth among all states in wind energy generation capacity, according to the American Wind Energy Association (AWEA).39 PSCo also purchases power from SunEdison’s 8.3-MW central PV solar plant near Alamosa, and has announced a power purchase agreement with Sun- Power, who is building a 17 MW PV plant adjacent to the SunEdison plant.40
Several factors provided renewable energy development initial momentum in Colorado. The state has a highly-educated population that is widely committed to improving the state’s environmental qual- ity. Colorado is also the home to several scientific research institutions, including the NREL, and the Colorado Renewable
Energy Collaboratory, referenced later in this report.
Colorado has abundant renewable resources. Colorado’s Eastern Plains has high-quality wind resources, and most parts of the state enjoy an average of 300 sunny days per year. In addition, a variety of important initiatives established Colo- rado’s leadership in renewable energy. These included, but are not limited to several important steps. PSCo pioneered a voluntary “green pricing” WindSource offering, which was started in 1997, and now supports more than 60 MW of wind. In 2001, the PUC determined that a large commercial wind plant was the most cost-effective new generation bid, save one small hydro plant.41 This led to devel- opment of the 162 MW Colorado Green wind project in Prowers County. Another key development was the Interwest En- ergy Alliance’s 2006 “backcasting” study, Wind on the Public Service Company of Colorado System: Cost Comparison to Natural Gas, which documented the cus- tomer cost savings of wind energy.42
Many consider the 2004 adoption of a RES as the most significant event in Colo- rado’s progress to advance renewable energy. Proponents collected 115,000 sig- natures to place a measure on the state- wide ballot, and Colorado voters passed
Should Colorado decide to implement the 20x20 goal, it is unlikely that
new coal-fired generation would be added to the energy mix unless the
plants contain major advances in carbon capture and storage.
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Amendment 37 in November 2004. This was the first state RES to be achieved by a popular vote. At that time, in 16 other states, RES laws were supported either through legislative or regulatory actions. Now, 36 states have similar RES laws.
Amendment 37 required IOUs t